Field of the Invention
The present invention relates to an integrated process for simultaneous removal and value addition to the sulfur and aromatics compounds of gas oil. More particularly, the present invention relates to the innovative application of salient features of distillation, solvent extraction and hydrodesulphurization processes to provide an efficient, cost effective and environment friendly integrated process for gas oil processing resulting in drastic performance enhancement of hydrotreating zone for removal of sulfur, enhancement in cetane number and value addition to its sulfur and aromatics compounds of gas oil.
Background Information
Sulfur limitation in gas oil was initially being implemented to reduce the emissions of the oxides of sulfur, generated during the combustion, which leads to acid ozone and smog and to meet the sulfur specification required for its processing in secondary process. The performance of emission control technologies is adversely affected by sulfur, polyaromatics and nitrogen compounds in gas oil. Therefore, continuously increasing trend of producing the ultraclean gas oil with strict specifications of sulfur and polyaromatics in gas oil is an effort to reduce the automobile emissions such as oxides of sulfur oxides of nitrogen (NOx), sunburn hydrocarbon compounds (HC) and particulate matter (PM) by reducing the sulfur and PAH in gas oil and to facilitate the implementation of advanced emission control technologies [DECSE; AECC; Koltai, T., 2002].
Hydrotreating is the most commonly used process in refinery for removal of sulfur and reducing the di and polyaromatics content in gas oil. Gas oil contains sulfur species including sulfides, thiols, thiophenes, benzothiophene, dibenzothiophene, a benzonaphthaothiophene with and without alkyl substituents [Hua R. et al.; Journal of chromatography A: Volume 1019, issue 1-2, Nov. 26, 2003 pp. 101-109]. Paul R. Robinson and Geoffrey E. Dolbear reported that rate of hydrodesulfurization is strong function of nature of sulfur compound. The relative rates of various sulfur compounds have been tabulated in Table 1. [Paul R. Robinson and Geoffrey E. Dolbear; Hydrotreating and hydrocracking: Fundamentals; Practical Advances in Petroleum Processing (Chang S. Hsu, Paul R. Robinson, ISBN: 978-0-387-25811-9), pp. 177-218].
TABLE 1Relative Rate of Hydrodesulphurization of Sulfur CompoundsSulfur compoundRelative HDS rateRemarkThiophene100easyBenzothiophene50easyDibenzothiophene30difficult4-Methy dibenzothiophene5More difficult4,6-Dimethyldibenzothiophene1Most difficult2,3,6-Trimethy dibenzothiophene1Most difficult
It is clear that alkyl substituted dibenzothiophes and debenzonapthiophene are refractive sulfur compounds for desulfurization. Further, it is well reported in literature that condensed polyaromatics in gas oil inhibits the desulfurization of refractive sulfur compounds significantly due to competitive adsorption of these aromatics on catalyst active sites [T. Koltai, M. Macauda, A. Guevara, E. Schulz. Comparative inhibiting effect of polycondensed aromatics and nitrogen compounds on the hydrodesulfurization of alkyldibenzothiophenes].
Therefore, deep reduction of sulfur and poly aromatics in gas oil using hydrotreating requires either constriction of new high pressure hydrotreating unit or substantial retrofitting of existing hydrotreating facilities, e.g., by integrating new high pressure rector with the existing reactor, by increasing catalyst volume, by using higher hydrogen to oil ratio, by incorporating gas purification system, by reengineering of reactor internals configuration, by employment of more reactive catalyst etc. Retrofitting of existing facilities shall also requires either new equipment or revamp of existing equipment such as makeup compressor due to significant increase in hydrogen consumption, recycle gas compressor due to increased recycle gas flow and pressure drop, vessels due to hydraulic issues, and the amine treating unit for the treating the additional gas rate. Moreover, installation of new grass root hydrogen plant or revamp of existing H2 plant for capacity enhancement would also be required to meet significant increase in H2 consumption due to high severity and polyaromatics saturation. All these options lead to massive initial plant capital investment. Further, severe operating conditions requirement leads to significant increase in operational cost and higher GHG emission to environment [E. R. Palmer, PTQ; Ismagilov, Z.; Less Harwell].
Considering above, refiners are seriously looking for alternative nonconventional processes which could be cost effective, flexible and environment friendly. The development of nonhydrotreating processes for desulfurization of gas oil has been widely studies. Some processes are based on oxidative desulfurization which includes the solvent extraction and adsorption process to remove the oxidized sulfur compounds from oxidized middle distillate. Oxidative desulfurization seems attractive for several reasons; relatively mild operating conditions, e.g., temperature from room temperature to 200° C., pressure from 1 to 15 atmospheric; higher reactivity of refractive sulfur compounds due to high electron density at the sulfur atom caused by attached electron rich aromatic rings. Electron density is further increased with presence of additional alkyl groups on the aromatic rings. [Otsuki, S. et al. oxidative desulfurization of light gas oil and vacuum gas oil by oxidation and solvent extraction. Energy and fuels. 14:1232-1239 (2000)].
Moreover, some integrated desulfurization processes incorporating both hydrodesulphurization and oxidative desulfurization are also reported in literature. The brief summary of some of the references disclosing the integrated processes are given below:
Cabrera et al. U.S. Pat. No. 6,171,478 discloses a process where hydrocarbon feed stock is first hydro treated in hydrotreating reaction zone containing hydrodesulphurization catalyst to remove certain sulfur compounds. Hydro treated stream is then contacted with the oxidant and catalyst in oxidation zone to oxidize the sulfur compounds. The oxidized sulfur compounds are removed from the oxidized hydrocarbon stream using the selective solvent extraction. Adsorption step is used to polish the oxidized sulfur compounds lean stream to reduce the sulfur content to desired level. Finally, stream containing oxidized sulfur compounds and hydrocarbon stream with reduced sulfur are obtained.
Kocal U.S. Pat. No. 6,277,271 disclose a process integrating the hydrodesulfurization and oxidative desulfurization. In this process, the reduced sulfur stream was obtained by carrying out the hydrodesulfurizion of initial hydrocarbon feed stream. Hydrotreated stream is fed to oxidation reaction zone along with oxidizing agent and catalyst to oxidize the residual sulfur compound to their corresponding sulfones. Oxidized sulfur compounds are removed in one stream and oxidized sulfur compounds lean hydrocarbon stream is recovered in second stream.
Wittenbricnk et al. U.S. Pat. No. 6,087,544 discloses a process for the production of high lubricity low sulfur distillate fuels. Feed stream is first fractionated into a light fraction containing from 50 to 100 ppmw of sulfur, and a heavy fraction. The light fraction is passed to a hydrodesulfurization reaction zone. Part of the desulfurized light fraction is blended with the certain part of heavy fraction to produce a low sulfur distillate fuel to meet the sulfur specification of 500 ppmw and lubricity requirement. It does not disclose further treatment of remaining heavy fraction of gas oil which is not blended with hydrodesulfurized light fraction.
Rappas et al. PCT publication WO 02/18581 discloses a process in which feed stock is hydrotreated in hydrodesulphurization reaction zone in presence catalyst and hydrogen. The entire hydrotreated stream is subjected to oxidation reaction zone which utilizes the hydrogen peroxide and formic acid to oxide the sulfur compounds. The stream, containing oxidized sulfur compounds, is further subjected to liquid-liquid extraction to remove the sulfones and to generate the hydrocarbon stream containing reduced sulfur level.
Levy et al. PCT application WO 03/014266 describes a process in which hydrocarbon stream is fed to oxidation reaction zone to convert the sulfur compounds into their corresponding sulfones using an aqueous oxidizing agent. After separating the oil phase of oxidation mixture, it is subjected to hydrodesulphurization.
Gong et al. U.S. Pat. No. 6,827,845 describes a process in which entire petroleum distillate is subjected to hydrodesulphurization reactor in presence of hydrogen and catalyst. After separating the hydrotreated oil from hydrogen and other lighter gas, it is fractionated in two fractions. The lighter fraction is either subjected to oxidation or blended with the stream obtained from oxidative desulfurization of heavy fraction. Heavy fraction of hydrotreated stream is subjected to oxidation reaction zone free from catalytically active metals using the peracids. The process requires very highH2O2: S molar ratio; in one of the example is 640 which is extremely high as compared to oxidative desulfurization with a catalytic system.
Gong et al U.S. Pat. No. 7,252,756 discloses a process for preparation of components for refinery blending of transportation fuels having a reduced amount of sulfur and/or nitrogen-containing impurities. In the process, a hydrocarbon feedstock containing the above impurities is contacted with an immiscible phase containing hydrogen peroxide and acetic acid in an oxidation zone. The hydrocarbon phase from aqueous phase is separated using the gravity principle. Then, this phase is passed to an extraction zone wherein aqueous acetic acid is used to extract a portion of any remaining oxidized impurities. A hydrocarbon stream having a reduced amount of sulfur and/or nitrogen-containing impurities is recovered. The acetic acid phase effluents from the oxidation and the extraction zones were routed to a common separation zone for recovery of the acetic acid. The recovered acetic acid is optionally recycled back to the oxidation and extraction zones.
Koseoglu et al., EP 2652089 A2, Pub. No. U.S. 2012/0145599A discloses an integrated process for desulfurization and denitrification. In the process first, entire hydrocarbon feed is hydrotreated to produces a hydrotreated effluent with lower content of labile organosulfur compounds. Thereafter, entire hydrotreated effluent is subjected to an extraction zone to produce an extract and raffinate. Extract contains major proportion of the aromatic content of the hydrotreated effluent and a portion of the extraction solvent. Raffinate contains a major proportion of the non-aromatic content of the hydrotreated effluent and a portion of the extraction solvent. Solvent removal from both extract and raffinate phases are proposed using flashing or striping or suitable apparatus. Solvent free aromatic-rich fraction extract is subjected to oxidation zone in presence of oxidizing agent and metal catalyst. Oxidized sulfur compounds were removed from oxidized aromatic rich extract using solvent extraction and adsorption to make final aromatic fraction with 10 ppmw sulfur.
Koseoglu et al. U.S. Pat. No. 8,741,128B2 discloses an integrated desulfurization and denitrification processes which includes mild hydrotreating of aromatic lean fraction and oxidation of aromatic rich fraction. In this process entire hydrocarbon feed stock is subjected to solvent extraction. The sulfur and aromatic lean hydrocarbon stream from extraction zone along with hydrogen is subjected to hydrodesulfurization reaction zone containing metal catalyst. The aromatic and refractive sulfur compound containing stream from extraction zone is subjected to oxidation reaction zone with an oxidizing agent and metal catalyst. The oxidized aromatic and sulfur rich stream is subjected to liquid—liquid extraction to remove oxidized sulfur compounds and finally the hydrocarbon stream containing reduced level of aromatics and sulfur is subjected to adsorption to meet the sulfur specification of 10 ppmw. However, after mixing the both fractions (raffinate from extraction zone and oxidation zone), sulfur in final product is in the range of 40-50 ppmw.
The person of ordinary skill in the art can understand that above references do not disclose a suitable and cost effective process required for deep desulfurization of gas oil. Most of the conventional processes do not target the different classes of sulfur and aromatic compounds having significant different relative reactivity to the conditions of hydrodesulphurization for minimizing the severity of hydrotreating reaction zone and for reducing the operational and equipment capital cost. In the conventional processes disclosed in prior art entire feed stream is subjected either to solvent extraction or hydrodesulphurization or oxidative desulfurization or adsorptive desulfurization or their combination for deep removal of sulfur compounds. This results the size of unit operations involved in the process dimensioned to the entire flow of feed. Process disclosed in the U.S. Pat. No. 8,741,128B2 and EP 2652089 A2 try to attempt the management of the different classes of sulfur compounds for making the desulfurization process more cost effective. However, in these processes also entire gas oil stream was subjected to solvent extraction process to generate the aromatic, sulfur and nitrogen compounds rich and lean hydrocarbon fractions of gas oil. Further, only the aromatic rich fraction of gas oil is subjected to oxidation zone to reduce the size of oxidation reaction zone and associated separations units such as solvent extraction and adsorption.
Person of the ordinary skilled in the art can understand that infrastructure and operational economics of the oxidative based process in refinery does not seems good due to various reasons; need of new facilities installation for generation of oxidants; installation of number of equipment for separation of unconverted oxidants, water, homogeneous catalyst using either distillation or some other methods, separation of oxidized sulfur compounds from non-sulfur compounds using either solvent extraction which needs extraction and solvent recovery facilities or adsorption which needs adsorption and regeneration facilities or combination of both. Generally, oxidant to sulfur molar ratio of greater than 4 is required in oxidative desulfurization, therefore for high sulfur stream the amount of oxidant will be huge. Thus, it seems evident from above discussion that savings in oxidative desulfurization based process due to less sever operating conditions and no hydrogen requirement would be watered down due to need of expensive oxidants, catalyst and number of new equipment for oxidation, separation of components of oxidized stream and separation of oxidized sulfur compounds.
Moreover, in the disclosed prior arts wherein entire hydrocarbon stream having boiling range of 170-400° C. subjected to solvent extraction and oxidative zone of the process shall lead to capital intensive process with huge operating cost and energy requirement. Person of the ordinary skilled in the art can understand that economics of extraction and oxidative desulfurization using solvent extraction for sulfones removal greatly depends on the nature of solvent used. Solvent recovery for its reuse from extract and raffinate phase is essential in extractive and oxidative based processes as solvent is far expensive than gas oil and its presence will affect the secondary process to be used for gas oil utilization. The simplest and most economical design of solvent recovery section is based on distillation and striping. However, person of the ordinary skilled in the art can understand that for utilization of this simple design, there should be temperature difference of at least 50-80° C. between boiling point of solvent and initial boiling point of feed to recover solvent from extract and raffinate phases. For lower temperature difference significant amount of hydrocarbon will contaminate the recovered solvent to achieve the target of trace amount of solvent in extract hydrocarbons. Thus, for treating the entire hydrocarbon stream having boiling range of 170-400° C. in extraction and oxidation with using simple distillation based solvent recovery, only low boiling solvents polar solvents such as methanol, ethanol, acetonitrile have to be used. However, it is reported in literature that sulfur and aromatic removal efficiency of these solvent is very poor (Otsuki, S., Nonaka, T., Takashima, N., Qian, W., Ishihara, A., Imai, T., Kabe, T. Oxidative desulfurization of light gas oil and vacuum gas oil by oxidation and solvent extraction. Energy Fuels. 2000; 14:1232-1239). Thus, application of these solvent need very high solvent to feed ratio which will result in significant increase in size of extraction unit and huge energy requirement to vaporize that huge quantity of solvent. Moreover, suitable and industrial proven solvents such as furfural, N-methyl 2-pyrrolidone, dimethylformamide and dimethylsulfoxide for sulfur and aromatic removals have high boiling point. Thus, application of these solvent in solvent extraction and oxidative desulfurization need a complicated design of solvent recovery wherein dissolved hydrocarbon in solvent (extract phase) can be recovered using secondary light boiling hydrocarbon solvent in subsequent extractor unit. Thereafter, secondary solvent can be recovered using distillation and striping. The design of solvent recovery sections needs more number of equipment and significant higher energy requirement compared to simple distillation and striping based design. Moreover, subjecting the entire middle distillate to the extraction process will not only need high operating cost but also lead significant loss of desired hydrocarbon with extract phase. Moreover, person skilled in the art can understand that in case of oxidized stream containing very high aromatics as 80% reported in Koseoglu et al., EP 2652089 A2, the yield of raffinate obtained from extraction of oxidized hydrocarbon will be lower and would not be also very lean in aromatics compounds.
In view of above, there is a need to develop a cost effective and energy efficient process which can overcome the disadvantages of processes disclosed in prior art for desulfurization of gas oil. The present invention is to provide an integrated process to overcoming the problems set forth above and to provide a cost effective, easy to retrofitting in existing hydrotreating process in refineries for removal of sulfur and di & poly aromatic compounds from gas oil.